Direct steam generator degassing

ABSTRACT

Systems and methods generate steam mixed with desired non-condensable gas concentrations using a direct steam generator. Injecting the steam into a reservoir may facilitate recovering hydrocarbons from the reservoir. Cooling an output of the direct steam generator produces water condensate, which is then separated from the non-condensable gas, such as carbon dioxide. Reducing pressure of the condensate subsequently heated by cross-exchange with effluent of the direct steam generator regenerates the steam with the carbon dioxide removed for the injection.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a non-provisional application which claims benefitunder 35 USC §119(e) to U.S. Provisional Application Ser. No. 61/940,962filed Feb. 18, 2014, entitled “ DIRECT STEAM GENERATOR DEGASSING,” whichis incorporated herein in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH

None.

FIELD OF THE INVENTION

Embodiments of the invention relate generally to generating steam thatmay be utilized for injection in thermal oil recovery processes.

BACKGROUND OF THE INVENTION

Enhanced oil recovery processes employ thermal methods to improverecovery of heavy oils from subsurface reservoirs. For example,injection of steam into heavy oil bearing formations heats the oil inthe reservoir, which reduces the viscosity of the oil and allows the oilto flow to a collection well. A mixture of the oil and produced waterthat flows to the collection well is recovered to the surface where theoil is separated from the water.

Different approaches exist for generating the steam. Prior once throughsteam generators (OTSGs) produce a wet steam by a single pass of waterthrough a boiler isolated from fluid communication with combustion usedto heat the boiler. An alternative approach utilizes a direct steamgenerator (DSG) to produce steam by contacting water with products fromoxy-fuel combustion.

Effluent from the DSG thus includes carbon dioxide along with the steamfrom water vaporization and the combustion to limit water replenishingrequirements. While some carbon dioxide injection may enhancehydrocarbon recovery and provide another advantage over the OTSG, excesscarbon dioxide may cause an adverse impact on the recovery. The DSG canonly provide a narrow range of carbon dioxide concentrations even thoughless or no carbon dioxide may be more effective.

Therefore, a need exists for systems and methods to generate steam withdesired concentrations of carbon dioxide and that are more costefficient.

BRIEF SUMMARY OF THE DISCLOSURE

In one embodiment, a method of recovering hydrocarbons with steamincludes vaporizing water by direct contact of the water with combustionproducts to produce a resulting fluid including the steam and carbondioxide. The method further includes cooling the fluid to provide amixture of the carbon dioxide and water condensate, separating a gasphase with the carbon dioxide from a liquid phase with the condensate,and regenerating the steam by reducing pressure and then heating thecondensate in a heat exchanger for thermal transfer with the fluid.Recovery of the hydrocarbons relies on injecting into a formation thesteam with the carbon dioxide removed.

According to one embodiment, a system for recovering hydrocarbons withsteam includes a steam generator in which water vaporizes by directcontact with combustion products to produce a resulting fluid includingthe steam and carbon dioxide. The system further includes a coolercoupled to receive the fluid from the steam generator for reducingtemperature of the fluid to form a mixture of the carbon dioxide andwater condensate, a separation vessel coupled to the cooler for removinga gas phase with the carbon dioxide from a liquid phase with thecondensate and a pressure reducer coupled between an outlet for thecondensate from the vessel and a heat exchanger forming at least part ofthe cooler to regenerate the steam at less pressure than the steamoutput from the steam generator using heat from the fluid output by thesteam generator. At least one injection well couples to the pressurereducer for introducing into a formation the steam with the carbondioxide removed.

For one embodiment, a method of degassing an output from direct steamgeneration includes vaporizing water by direct contact of the water withcombustion products to produce a resulting fluid including steam andcarbon dioxide. In addition, the method includes cooling the fluid in aheat exchanger and then a cooling unit to liquefy the steam into a watercondensate at a first pressure and separating the carbon dioxide in agaseous phase from the condensate. The steam regenerates at a secondpressure lower than the first pressure by passing the condensate througha pressure reducer and then the heat exchanger for thermal transfer withthe fluid.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the present invention and benefitsthereof may be acquired by referring to the following description takenin conjunction with the accompanying drawings in which:

FIG. 1 is a schematic of a system for degassing steam from a directsteam generator prior to injection into a hydrocarbon reservoir,according to one embodiment.

DETAILED DESCRIPTION

Turning now to the detailed description of the preferred arrangement orarrangements of the present invention, it should be understood that theinventive features and concepts may be manifested in other arrangementsand that the scope of the invention is not limited to the embodimentsdescribed or illustrated. The scope of the invention is intended only tobe limited by the scope of the claims that follow.

Embodiments of the invention relate to systems and methods of generatingsteam mixed with desired non-condensable gas concentrations using adirect steam generator. Recovering hydrocarbons from a reservoir mayrely on injecting the steam into a reservoir. Cooling an output of thedirect steam generator produces water condensate, which is thenseparated from the non-condensable gas, such as carbon dioxide. Reducingpressure of the condensate subsequently heated by cross-exchange witheffluent of the direct steam generator regenerates the steam with thecarbon dioxide removed for the injection.

FIG. 1 illustrates a system for recovering hydrocarbons that includes aprocessing unit 102, a direct steam generator or DSG 108, a cooler(e.g., a heat exchanger 116 and/or a cooling unit 118), a firstseparator 120, a pressure reducer 122 and a second separator 124 thatare all coupled to at least one production well 100 and at least oneinjection well 126. In an exemplary embodiment, the injection well 126and the production well 100 provide a well pair for a steam assistedgravity drainage (SAGD) operation. Various other recovery operationsincluding cyclic steam stimulation, solvent aided SAGD and steam drivemay also employ processes described herein.

In operation, the processing unit 102 receives a mixture that isrecovered from the production well 100 and includes hydrocarbons or oiland condensate from steam that is injected to heat and mobilize the oil.The processing unit 102 may include liquid-gas separators, water-oilseparators and treatment equipment for gas and water. The processingunit 102 separates the mixture into a sales stream 104 of the oil and asteam generator feed stream 106 of water.

The direct steam generator 108 burns fuel, such as produced gas, naturalgas, methane, or combinations thereof, from fuel inlet 112, in oxygenwithin a combustor where the water from the feed stream 106 is alsointroduced. An air separation unit (ASU) output 110 may supply theoxygen to the direct steam generator 108. The oxygen plant may producepure oxygen or may contain some impurities dependent upon the type ofseparation. Oxygen enriched air may be 25-50% oxygen, but typicallypurified oxygen is used with concentrations above 90%, preferably above95%, and may even be above 97.5% to 99.5%. A fluid output 114 from thedirect steam generator 108 thus conveys non-condensable gas products ofcombustion, such as carbon dioxide or other gases having a boiling pointlower than conditions in the reservoir into which the steam is injected,along with steam from both water vaporization and the combustion to theheat exchanger 116.

In some embodiments, the DSG 108 superheats the steam in the output 114.The DSG 108 may include a solids removal device for filteringparticulates caused by impurities in the water remaining once the wateris vaporized. Alternative approaches may provide the steam at saturationor without complete vaporization such that wet steam passes to the heatexchanger 116 or is separated to provide saturated steam supplied to theheat exchanger 116.

The heat exchanger 116 cools the steam in the output 114 from the DSG108 to condense at least some of the steam (e.g., at least ninetypercent by weight) into water condensate. The cooling unit 118 furtherdecreases temperature of the steam that remains after passing throughthe heat exchanger 116 to provide additional condensation. The use ofcooling unit 118 provides additional cooling reducing the temperaturechange across heat exchanger 116 allowing a smaller heat exchanger to beused, but could increase the amount of steam losses via stream 128because it is unlikely that all the water exiting the bottom ofseparator 120 could then be revaporized in exchanger 116. Thus there isa tradeoff between the cost of a smaller heat exchanger 116 and theincreased steam losses via water in stream 128. The additionalcondensation attained from cooling unit 118. This additionalcondensation may cause all of the water to be in liquid phase uponexiting the cooling unit 118 and thus cause flow from the cooling unitto be at least eighty percent liquid by weight or between eighty-threeand ninety-three percent liquid by weight.

Temperature and pressure conditions of outflow from the cooling unit 118may be below the boiling point of water without need for further coolingand such that the non-condensable gases remain in the gaseous phase. Insome embodiments, the cooling unit 118 relies on external heatdissipation such that thermal energy is transferred independent of fluidflows downstream from the DSG 108. The cooling unit 118 may utilize heatexchange with streams integrated in operations other than steamgeneration or employ fans for air based heat dissipation.

The outflow from the cooling unit 118 enters the first separator 120where phase separation removes gases including the carbon dioxide fromthe water condensate. Steam entering the separator will exit with thecarbon dioxide gas stream and represent a loss from the system, as willsome of the finer water droplets because gas-liquid separators are not100% efficient. The separator losses to steam can be minimized byincluding them in the optimization of cooler 118 discussed above, andthe losses to water droplets can be minimized by good separator design.The carbon dioxide exits from an overhead of the first separator 120 andmay be exhausted or conveyed to a sequestration site distinct from theformation into which the steam is desired for injection with limited orno carbon dioxide co-injection. The condensed water exiting a lowerportion of the separator 120 passes through the pressure reducer 122.

For some embodiments, the pressure reducer 122 includes at least one ofan orifice and a throttling valve. The condensate remains at asufficient temperature such that this drop in pressure may flash part ofthe condensate to regenerate at least some of the steam, albeit degassedand at less pressure than the steam in the output 114 from the DSG. Inone embodiment, the pressure reducer 122 reduces the pressure of thecondensate by at least 6500 kilopascals (kPa) or at least 3500 kPa.

The DSG 108 in some embodiments provides the steam in the output 114 ata first pressure between 10,000 and 14,500 kPa and the steam that isinjected into the formation is at a second pressure between 5500 and10,000 kPa. Operating temperatures selected depend on these respectivepressures and achieve phase changes as described herein. To obtaininitial pressurization, pumps may supply the water to the DSG 108 atdesired pressures.

This degassed stream or wet steam exiting the pressure reducer 122passes through the heat exchanger 116, which vaporizes the water tosteam as well as recovers heat due to thermal transfer upon cooling thesteam from the output 114 of the DSG 108. The resulting degassed steammay feed into the second separator 124 for condensate removal prior tointroduction into the injection well 126. The steam supplied to theinjection well 126 may thereby contain limited or no carbon dioxide andbe saturated. The condensate 128 from the second separator 124 may berecycled back to the feed stream 106 for supply to the DSG 108 or usedelsewhere in the SAGD process integration.

In closing, it should be noted that the discussion of any reference isnot an admission that it is prior art to the present invention,especially any reference that may have a publication date after thepriority date of this application. At the same time, each and everyclaim below is hereby incorporated into this detailed description orspecification as additional embodiments of the present invention.

Although the systems and processes described herein have been describedin detail, it should be understood that various changes, substitutions,and alterations can be made without departing from the spirit and scopeof the invention as defined by the following claims. Those skilled inthe art may be able to study the preferred embodiments and identifyother ways to practice the invention that are not exactly as describedherein. It is the intent of the inventors that variations andequivalents of the invention are within the scope of the claims, whilethe description, abstract and drawings are not to be used to limit thescope of the invention. The invention is specifically intended to be asbroad as the claims below and their equivalents.

1. A method of recovering hydrocarbons with steam, comprising:vaporizing water by direct contact of the water with combustion productsto produce a resulting fluid including the steam and carbon dioxide;cooling the fluid to provide a mixture of the carbon dioxide and watercondensate; separating a gas phase with the carbon dioxide from a liquidphase with the condensate; regenerating the steam by reducing pressureand then heating the condensate in a heat exchanger for thermal transferwith the fluid; and injecting into a formation the steam with the carbondioxide removed for recovery of the hydrocarbons.
 2. The method of claim1, wherein the cooling of the fluid includes passing the fluid throughthe heat exchanger and then passing the fluid through a cooling unitthat dissipates heat independent of flows resulting from the vaporizingof the water.
 3. The method of claim 1, wherein the reducing of thepressure includes passing the condensate through at least one of anorifice and a throttling valve.
 4. The method of claim 1, furthercomprising recycling to vaporize a liquid component that is separatedfrom the steam following the reducing of the pressure and the heating inthe heat exchanger.
 5. The method of claim 1, wherein the gas phase withthe carbon dioxide is conveyed to a sequestration site distinct from theformation with the hydrocarbons.
 6. The method of claim 1, wherein thefluid is at a first pressure between 10,000 and 14,500 kilopascals (kPa)and the steam that is injected into the formation is at a secondpressure between 5500 and 10,000 kPa.
 7. The method of claim 1, whereinthe separating of the gas phase results in the steam that is injectedhaving less than ten percent of the carbon dioxide from the fluid. 8.The method of claim 1, wherein the mixture of the carbon dioxide and thewater condensate prior to separation is at least eighty percent liquidby weight.
 9. The method of claim 1, wherein the mixture of the carbondioxide and the water condensate prior to separation is betweeneighty-three and ninety-three percent liquid by weight.
 10. The methodof claim 1, wherein the vaporizing of the water provides the steam thatis superheated.
 11. A system for recovering hydrocarbons with steam,comprising: a steam generator in which water vaporizes by direct contactwith combustion products to produce a resulting fluid including thesteam and carbon dioxide; a cooler coupled to receive the fluid from thesteam generator for reducing temperature of the fluid to form a mixtureof the carbon dioxide and water condensate; a separation vessel coupledto the cooler for removing a gas phase with the carbon dioxide from aliquid phase with the condensate; a pressure reducer coupled between anoutlet for the condensate from the vessel and a heat exchanger formingat least part of the cooler to regenerate the steam at less pressurethan the steam output from the steam generator using heat from the fluidoutput by the steam generator; at least one injection well coupled tothe pressure reducer for introducing into a formation the steam with thecarbon dioxide removed.
 12. The system of claim 11, wherein the coolerincludes the heat exchanger and a cooling unit that dissipates heatindependent of flows from the steam generator.
 13. The system of claim11, wherein the pressure reducer is at least one of an orifice and athrottling valve.
 14. The system of claim 11, further comprising arecycle conduit coupled to supply the steam generator with a liquidcomponent separated from the steam regenerated after the pressurereducer and the heat exchanger.
 15. The system of claim 11, furthercomprising a sequestration site distinct from the formation with thehydrocarbons and where the gas phase with the carbon dioxide isconveyed.
 16. The system of claim 11, wherein the steam generatoroperates at a first pressure between 10,000 and 14,500 kilopascals (kPa)and the pressure reducer is configured to provide the steam that isinjected into the formation at a second pressure between 5500 and 10,000kPa.
 17. A method of degassing an output from direct steam generation,comprising: vaporizing water by direct contact of the water withcombustion products to produce a resulting fluid including steam andcarbon dioxide; cooling the fluid in a heat exchanger and then a coolingunit to liquefy the steam into a water condensate at a first pressure;separating the carbon dioxide in a gaseous phase from the condensate;and regenerating the steam at a second pressure lower than the firstpressure by passing the condensate through a pressure reducer and thenthe heat exchanger for thermal transfer with the fluid.
 18. The methodof claim 17, wherein the separating results in the steam at the secondpressure having less than ten percent of the carbon dioxide from thefluid.
 19. The method of claim 17, wherein a mixture of the carbondioxide and the water condensate prior to the separating is betweeneighty-three and ninety-three percent liquid by weight.
 20. The methodof claim 17, wherein the pressure reducer is at least one of an orificeand a throttling valve.